This invention relates generally to the field of well production apparatus such as used, for example, in down-hole pumping systems in wells. It also relates to pumping apparatus and methods for use of that apparatus.
Specific challenges arise in oil production when it is desired to extract heavy, sandy, gaseous or corrosive high temperature oil and water slurries from underground wells. These slurries to be pumped range over the breadth of fluid rheology from highly viscous, heavy, cold crude to hot thermal fluids. Recent technological advances have permitted wells to be sunk vertically, and then to continue horizontally into an oil producing zone. Thus wells can be drilled vertically, on a slant, or horizontally. To date, although equipment is available to drill these wells, at present there is a need for a relatively efficient, and reasonably economical means to extract slurries from wells of these types.
In particular, it would be desirable to have a type of pump that would permit relatively efficient extraction of oil slurries from underground well bores that include horizontal and steam assisted gravity drainage (SAGD) or non-thermal conventional wells. In one SAGD, process twin horizontal wells are drilled in parallel, one somewhat above the other. Steam is injected into the upper bore. This encourages oil from the adjacent region of the oil bearing formation to drain toward the lower bore. The production fluids drawn from the lower bore can then be pumped from the lower bore to the surface.
It is advantageous to match the pumping draw down of the lower bore to the rate of steam injection used in the upper bore. This will depend on the nature of the oil bearing formation, the viscosity of the oil and so on. If the rates can be matched to achieve a relative balance, the amount of steam pressure required can be reduced, thus reducing the power of the steam injection system required, and resulting in a more economical process.
Pumping the production oil or slurry from the lower horizontal bore presents a number of challenges. An artificial lift, or pumping, system must be able to operate even when the xe2x80x9cliquidxe2x80x9d to be pumped is rather abrasive. For example, some design criteria are based on slurries that may contain typically 3% by weight, and for short periods as much as 30% by weight, of abrasives, such as sand The pumping technology must be capable of handling a high volume of formation solids in the presence of high gas oil ratios (GOR). The system may well be called upon to handle slugs of hydrocarbon gas and steam created by flashing of water into vapour. On occasion the system may run dry for periods of time. As such, it is desirable that the system be capable of processing gases, and of running xe2x80x9cdryxe2x80x9d. It is also desirable that a pump, and associated tubing, be able to operate to a depth of 1000 M below well-head, or more, with an allowance of 100 psi as the minimum flow-line input pressure. It is also desirable that the equipment be able to operate in chemically aggressive conditions where pH is +/xe2x88x9210.
Further still, it would be advantageous to be able to cope with a large range of viscositiesxe2x80x94from thick, viscous fluids to water, and at relatively high temperatures. The chosen equipment should be operable in both vertical and horizontal well bores.
Another requirement is the ability to pump all of the available fluid from the well bore. To that end it is advantageous to be able to operate the pump as far as possible in depth into a horizontal section. The system needs to be able to operate at high volume capacities, i.e., high volumetric flow rates, and to operate reasonably well under saturated steam conditions while processing hydrocarbon gases. As far as the inventors are aware, there is at present no artificial lifting equipment that addresses these problems in a fully satisfactory manner. It would be desirable to have a relatively efficient high temperature, high volume pumping system that can accommodate a large range of production requirements, with the capability of being installed into, and operating from, the horizontal section of a well bore.
Other artificial lift systems have been tried. For example, one known type of pump is referred to as a xe2x80x9cPump Jackxe2x80x9d. It employs sucker rod pumping with a down-hole plunger pump. This is a reciprocating beam pumping system that includes a surface unit (a gearbox, Pittman arms, a walking beam, a horsehead and a bridle) that causes a rod string to reciprocate, thereby driving a down-hole plunger pump.
Pump jack systems have a number of disadvantages. First, it is difficult to operate a down-hole reciprocating rod pump in a horizontal section because of the reliance on gravity to exert a downward force on the pump plunger. Further, a horizontal application may tend to cause increased pump wear due to curvature in the pump barrel (to get to the horizontal section) and increased sucker rod and tubing wear. Second, down-hole pumps are susceptible to damage from sand, high temperature operation, and other contaminants. Third, plunger pumps are prone to gas lock. Fourth, the downward stroke of the pump rod, being governed by gravity, is subject to xe2x80x9crod floatxe2x80x9d. That is, as the length of the rod increases, the rod itself has sufficient resiliency, and play, that the motion transmitted from the surface is not accurately copied at the plungerxe2x80x94it may be out of phase, damped, or otherwise degraded so that much pumping effort is wasted. Fifth, pump jacks tend to require relatively extensive surface site preparation. Horizontal units tend to require larger than normal pump units because of the need to activate (i.e., operate) the rod string around the bend of the xe2x80x9cbuild sectionxe2x80x9d as well as to lift the weight of the rod string.
Another type of pump is the progressive cavity pump, or screw pump. In this type of pump a single helical rotor, usually a hard chrome screw, rotates within a double helical synthetic stator that is bonded within a steel tube. Progressive cavity pumps also have disadvantages: First, they tend not to operate well, if at all, at high temperatures. It appears that the maximum temperature for continuous operation in a well bore is about 180 F. (80 C.). It is desirable that the pump be able to operate over a range of xe2x88x9230 to 350 C. (xe2x88x9220 to 650 F.), and that the pump be able to remain in place during steam injection. Second, progressive cavity pumps tend not to operate well xe2x80x9cdryxe2x80x9d. It is desirable to be able to purge hydrocarbon gases, or steam created by flashing water into vapour. As far as the present inventors are aware, progressive cavity pumps have not been capable of operation in high GOR conditions. Further, the synthetic stator material of some known pumps appears not to be suitable for operation with aromatic oils. Due to the design of the screws, and their friction fit, progressive cavity pumps tend to have little, if any, ability to generate high pressures, thereby restricting their use to relatively shallow wells. In addition, progressive cavity pumps tend to be prone to wear between the rotor and the stator, and tend to have relatively short service run lives between overhauls. Progressive cavity pumps do not appear to provide high operational efficiency.
Electric submersible pumps (ESP) include a down-hole electric motor that rotates an impeller (or impellers) in the pump, thereby generating pressure to urge the fluid up the tubing to the surface. Electric submersible pumps tend to operate at high rotational speeds, and tend to be adversely affected by inflow viscosity limitations. They tend not to be suitable for use in heavy oil applications. Electric submersible pumps tend to be susceptible to contaminants. Electric submersible pumps are not, as far as the inventors are aware, positive displacement pumps, and consequently are subject to slippage and a corresponding decrease in efficiency. The use of electric submersible pumps is limited by horsepower and temperature restrictions.
Jet pumps typically employ a high pressure surface pump to transmit pumping fluid down-hole. A down-hole jet pump is driven by this high pressure fluid. The power fluid and the produced fluid flow together to the surface after passing through the downhole unit. Jet pumps tend to have rather lower efficiency than a positive displacement pump. Jet pumps tend to require higher intake pressures than conventional pumps to avoid cavitation. Jet pumps tend to be sensitive to changes in intake and discharge pressure. Changes in fluid density and viscosity during operation affect the pressures, thereby tending to make control of the pump difficult. Finally, jet pump nozzles tend to be susceptible to wear in abrasive applications.
Gas lift systems are artificial lift processes in which pressurised or compressed gas is injected through gas lift mandrels and valves into the production string. This injected gas lowers the hydrostatic pressure in the production string, thus establishing the required pressure differential between the reservoir and the well-bore, thereby permitting formation fluids to flow to the surface. Gas lift systems tend to have lower efficiencies than positive displacement pumps. They tend be uncontrollable, or poorly controllable, under varying well conditions, and tend not to operate effectively in relatively shallow wells. Gas lift systems only have effect on the hydrostatic head in the vertical bore, and may tend not to establish the required drawdown in the horizontal bore to be beneficial in SAGD application. Further, gas lift systems tend to be susceptible to gas hydrate problems. The surface installation of a gas lift system may tend to require a significant investment in infrastructurexe2x80x94a source of high pressure gas, separation and dehydration facilities, and gas distribution and control systems. Finally, gas lift systems tend not to be capable of achieving low bottom-hole producing pressures.
Operation of a pump at a remote location in a bore hole also imposes a number of technical challenges. First, the pump itself can not be larger in diameter than the well bore. In oil and gas well drilling, for example, it can only be as large as permitted by the well-head blow-out preventer. A typical casing may have a diameter of 140 to 178 mm (5xc2xd to 7 inches). A typical production tube has a diameter in the range of 73 to 89 mm (2xc2xe to 3xc2xd inches). Providing power to a down-hole pump is also a challenge. An electric motor may burn out easily, and it may be difficult to supply with electrical power at, for example, ten thousand feet (3000 m) distance along a bore given significant line losses. A pneumatic or hydraulic pump can be used, provided an appropriate flow of working fluid is available under pressure. Whatever type of pump is used, it may tend to need to be matched in a combination with the available power delivery system.
In a number of applications, such as oil or other wells, it is desirable to conduct one or more types of fluid down a long tube, or string of tubing, while conducting another flow, or flows, in the opposite direction. Similarly, it may be advantageous to use a passageway, or a pair of passageways to conduct one kind of fluid, and another passageway for electrical cabling whether for monitoring devices or for some other purpose, or another pair of passageways for either pneumatic or hydraulic power transmission. In oil field operations it may be desirable to have a pair of passageways as pressure and return lines for hydraulic power, another line, or lines, for conveying production fluids to the surface, perhaps another line for supplying steam, and perhaps another line for carrying monitoring or communications cabling.
One method of achieving this end is to use concentrically nested pipes, the central pipe having a flow in one direction, the annulus between the central pipe and the next pipe carrying another flow, typically in the opposite direction. It may be possible to have additional annulli carrying yet other flows, and so on. Although singular continuous coiled tubing has been used, the ability to run an inner string within an outer concentric string is relatively new, and may tend to be relatively expensive. This has a number of disadvantages, particularly in well drilling. Typically, in well drilling the outside diameter of the pipe is limited by the size of the well bore to be drilled. This pipe size is all the more limited if the drilling is to penetrate into pockets of liquid or gas that are under pressure. In such instances a blow-out preventer (BOP) is used, limiting the outside diameter of the pipe. Typically, a drill string is assembled by adding modules, or sections of pipe, together to form a string. Each section is termed a xe2x80x9cjointxe2x80x9d. A joint has a connection means at each end. For example, one end (typically the down-hole end) may have a male coupling, such as an external thread, while the opposite, well-head, end has a matching female coupling, such as a union nut. It is advantageous in this instance to have a positive make-up, that is, to be able to join the xe2x80x9cjointsxe2x80x9d without having to spin the entire body of the joint, but rather to have the coupling rotate independently of the pipe.
A limit on the outside diameter of the external pipe casing imposes inherent limitations on the cross-sectional area available for use as passageways for fluids. In some instances three or four passages are required. For example, this is the case when a motive fluid, whether hydraulic oil or water, is used to drive a motor or pump, requiring pressure and return lines, while the production fluid being pumped out requires one or more passages. The annulus width for four passages nested in a 3.5 inch tube is relatively small. The inventors are unaware of any triple or quadruple concentric tube string that has been used successfully in field operations.
As the depth of the well increases, the downhole pressure drop in the passages also increases. In some cases the well depth is measured in thousands of metres. The pressure required to force a slurry, for example, up an annular tube several kilometres long, may tend to be significant. One way to reduce the pressure drop is to improve the shape of the passages. For example, in the limit as an annulus becomes thin relative to its diameter, the hydraulic diameter of the resultant passage approaches twice the width, or thickness, of the annulus. For a given volumetric flow rate, at high Reynolds numbers pipe losses due to fluid friction vary roughly as the fourth power of diameter. Hence it is advantageous to increase the hydraulic diameter of the various passageways. One way to increase the hydraulic diameter of the passage is to bundle a number of tubes, or pipes, in a side-by-side configuration within an external retainer or casing in place of nested annulli. The overall cross-sectional area can also be improved by dividing the circular area into non-circular sectors, such as passages that have the cross-section shape of a portion of a pie.
Another important design consideration in constructing a pipe for deep well drilling, or well drilling under pressure, is that the conduit used be suitable for operation in a blow out preventer. This means that the pipe must be provided in sections, or joints, that can be assembled progressively in the blow out preventer to create, eventually, a complete string thousands, or tens of thousands, of feet long. It is important that the sections fit together in a unique manner, so that the various passages align themselvesxe2x80x94it would not do for an hydraulic oil power supply conduit of one section to be lined up with the production fluid upward flow line of an adjacent section. Further, given the pressures involved, not only must the passage walls in each section be adequate for the operational pressure to which they are exposed, but the sections of pipe must have a positive seal to each other as they are assembled. Further still, given the relatively remote locations at which these assemblies may be used, and possibly harsh environmental conditions, the sections must go together relatively easily. It is advantageous to have a xe2x80x9cuser friendlyxe2x80x9d assembly for ease of pick-up, handling, and installation, that can be used in a conventional oil rig, for example.
Some of the tube passages must be formed in a manner to contain significant pressure. For an actual operating differential pressure in the range of 0-2000 p.s.i., it may be desirable to use pipe that can accommodate pressures up to, for example, 8,000 p.s.i. Seamless steel pipe can be obtained that is satisfactory for this purpose. Electrical resistance welded pipe (ERW) that is suitable for this purpose can also be obtained. The steel pipe can then be roll formed to the desired cross-sectional shape.
In an aspect of the invention there is a fluid displacement assembly having a first gear, a second gear, and a housing having a chamber defined therein to accommodate the gears. The first and second gears are mounted within the housing in meshing relationship. The housing has an inlet by which fluid can flow to the gears and an outlet by which fluid can flow away from the gears. The gears are operable to urge fluid from the inlet to the outlet, and at least a portion of the housing is made from a ceramic material.
In an additional feature of that aspect of the invention, the assembly is operable at temperatures in excess of 180xc2x0 F. In another additional feature, the assembly is operable at temperatures at least as high as 350xc2x0 F. In another additional feature, the ceramic material is part of a ceramic member, and is mounted within a casing. In still another feature, the ceramic material has a compressive pre-load.
In yet another feature the first and second gears are spur gears. In an alternative feature, the first gear is a spur gear and the second gear is a ring gear mounted eccentrically about the first gear. In a further feature, a ceramic partition member is mounted within the ring gear between the first gear and the second gear. In a further alternative feature, the first and second gears are a pair of gerotor gears.
In a further additional feature of the invention, the gears are sandwiched between a pair of first and second yokes mounted to either axial sides thereof Each of the yokes has a pair of first and second bores formed therein to accommodate first and second shafts. Each of the yokes has a gear engagement face located next to the gears. Each of the gear engagement faces has a peripheral margin conforming to the arcuate portions of the internal wall of the housing, and each of the yokes is biased to lie against the gears.
In another aspect of the invention there is a gear pump having a first gear, a second gear, and a housing having a chamber defined therein to accommodate the gears. The first gear is mounted on a shaft having an axis of rotation. The first and second gears are mounted in the housing in meshing engagement. The housing has an inlet by which fluid can flow to the gears and an outlet by which fluid can flow away from the gears, and the shaft is mounted in ceramic bushings within the housing. In another feature of that aspect of the invention, the ceramic bushings include ceramic inserts mounted in a metal body.
In a further aspect of the invention there is a gear pump having a first gear, a second gear, and a housing having a cavity defined therein to accommodate the first and second gears. The first and second gears are mounted in meshing relationship within the housing. The housing has an inlet by which fluid can flow to the gears and an outlet by which fluid can flow away from the gears. The gears are operable to displace fluid from the inlet to the outlet. The first gear is mounted on a first shift having a first axis of rotation. The first and second gears each have a first end face lying in a first plane perpendicular to the axis of rotation. A moveable wall is mounted within the housing to engage the first end faces of the gears. The moveable wall has a ceramic surface oriented to bear against the first end faces of the first and second gears.
In an additional feature of that aspect of the invention, the moveable wall is a head of a piston and, in operation, the piston is biased toward the first end faces of the first and second gears. In another feature, the piston is hydraulically biased toward the gears. In another feature, each of the first and second gears has a second end face lying in a second plane spaced from the first plane, and a second moveable wall is mounted within the housing to bear against the second end faces of the first and second gears. In another feature, both of the moveable walls are biased toward the gears. In another additional feature, the end walls are heads of respective first and second pistons, the pistons being moveable parallel to the axis of rotation. In a further additional feature, the ceramic surface is a plasma carried on a metal substrate.
In another additional feature, the second gear is mounted on a second shaft extending parallel to the first shaft. The ceramic surface is formed on a body having a first bore defined therein to accommodate the first shaft and a second bore defined therein to accommodate the second shaft, the body being displaceable along the shafts. In a further feature, at least one of the bores has a wall presenting a ceramic bushing surface to one of the shafts. In another feature the body has a passageway formed therein to facilitate flow of fluid. In a further feature, the body has passageways formed therein to facilitate flow of fluid to and from the inlet and the outlet.
In still another aspect of the invention, there is a gear pump assembly having a pair of first and second mating gears, mounted on respective first and second parallel shafts in meshed relationship; and a housing for the gears, the housing having an inlet by which fluid can flow to the gears and an outlet by which fluid can flow away from the gears. The gears are operable to urge fluid from the inlet to the outlet. The housing includes a gear surround having two overlapping bores defined therein conforming to the gears in meshed relationship, and the surround presents a ceramic internal surface to the gears.
In an additional feature the surround is formed of a transformation toughened zirconia. In a further feature, the surround is made of a ceramic monolith. In another feature, the surround has a compressive pre-load. In a still further feature, the surround is mounted within a shrink fit casing member. In yet another feature, the ceramic monolith has a co-efficient of thermal expansion corresponding to the co-efficient of thermal expansion of the gears. In another additional feature, the gear pump assembly has a movable endwall mounted to ride in the overlapping bores.
In another additional feature, the shafts each have an axis of rotation and the gears each have first and second end faces lying in first and second spaced apart parallel planes, the parallel planes extending perpendicular to said axis. A movable piston is mounted to ride within the overlapping bores, and the piston has a face oriented to engage the first end faces of the gears.
In another aspect of the invention, there is a gear pump assembly having a first gear mounted on a first shaft, the first shaft having a first axis of rotation; and a second gear mounted on a second shaft, the second shaft having a second axis of rotation, the axes lying in a common plane. The first and second gears are mounted to mesh together in a first region between the axes. A gear surround has an internal wall defining a cavity shaped to accommodate the gears. The internal wall has a first portion formed on an arc conforming to the first gear and a second portion, formed on another arc, to conform to the second gear. The first and second portions lie away from the first region. The internal wall has a third portion between the first and second portions. The third portion lies abreast of the first region and has a first passageway formed therein to carry fluid to the cavity adjacent to the gears to one side of the plane. The internal wall has a fourth portion lying between the first and second portions. The fourth portion lies abreast of the first region to the other side of the plane from the third portion. The fourth portion has a second passageway formed therein to carry fluid from the cavity. The gears are operable to transfer fluid from the first passageway to the second passageway.
In an aspect of the invention, there is a modular well pipe assembly. There is a pipe wall structure having at least first and second passages defined side-by-side therein. The pipe wall structure has a first end and a second end. The first and second ends have respective first and second end couplings matable with other end couplings of modular pipe assemblies of the same type. The end fittings have alignment fittings for aligning the first and second passages with corresponding first and second passages in other modular pipe assemblies of the same type.
In an additional feature of that aspect of the invention, the pipe wall structure includes a hollow outer casing and at least first and second conduits for carrying fluids mounted side-by-side within the casing. In another additional feature of that aspect of the invention, one of the end couplings has a seal mounted thereto. The seal has porting defined therein corresponding to the passages. The seal is placed to maintain segregation between the passages when the modular pipe assembly is joined to another modular pipe assembly of the same type. In yet another additional feature, the end coupling is engageable with a mating modular pipe assembly to compress the seal.
In still another additional feature, the pipe wall structure includes a first conduit member and a second conduit member mounted within the first conduit member. The first conduit member has a continuous wall. The continuous wall has an inner surface defining a periphery of an internal space. The second conduit member occupies a first portion of the internal space of the first conduit member and leaves a remainder of the internal space of the first conduit member. The second conduit member has a continuous wall. The continuous wall of the second conduit member has the second side by side passage defined therewithin.
The continuous wall of the second conduit has an external surface. A portion of the external surface of the second conduit member is formed to conform to a first portion of the inner surface of the first conduit member, and is located there adjacent. The first passage is defined within the remainder of the internal space of the first conduit member. In still yet another additional feature, the inner surface of the first conduit member has a second portion bounding a portion of the first passage.
In another additional feature of that aspect of the invention, the inner surface of the first conduit member has a second portion. The external surface of the second conduit member has a second portion. The second portion of the inner surface of the first conduit member and the second portion of the external surface of the second conduit member co-operate to bound at least a portion of the first passageway. In yet another additional feature of that aspect of the invention, the first conduit member has a round cylindrical cross-section. The second conduit member continuous wall has a portion lying along a first chord of the cylindrical cross-section. In still another additional feature, the chord is a diametrical chord. In another additional feature, the second conduit member has another portion lying along a second chord of the cylindrical cross-section. In a further additional feature of that aspect of the invention, the second conduit member occupies a sector of the cylindrical cross-section between the first and second chords.
In yet a further additional feature, the pipe wall structure includes a third conduit member. The third conduit member has a continuous wall having a third side-by-side passage defined therewithin. The third conduit member has an external surface. A portion of the external surface is shaped to conform to, and is located adjacent to a second portion of the inner surface of the first conduit member.
In still a further additional feature, the pipe wall structure includes a third conduit member. The third conduit member has a continuous wall having a third side-by-side passage defined therewithin. The second conduit member has an internal wall surface. The third conduit member continuous wall has an external surface. A portion of the external surface of the third conduit member is shaped to conform to, and is mounted against, a portion of the internal wall surface of the second conduit member.
In another additional feature of that aspect of the invention, the pipe wall structure includes a first conduit member, a second conduit member, and a third conduit member. The second and third conduit members are mounted side-by-side within the first conduit member. In yet another additional feature, the second conduit member has a circular cross-section. In still another additional feature, the second and third conduit members have circular cross-sections. In a further additional feature, a fourth conduit member is mounted within the first conduit member. In still a further additional feature, the first conduit member has a circular internal wall surface. The second, third and fourth conduit members have circular cross sections and are mounted in tangential engagement with the circular internal wall surface of the first conduit member. In another additional feature of that aspect of the invention, each of the second, third and fourth conduit members is tangent to at least one of the others. In still another additional feature, at least one of the second and third conduit members is hexagonal in cross-section.
In yet another additional feature, at least one of the second and third conduit members is pie shaped in cross-section. In a further feature of that aspect of the invention, the pie shape is chosen from the set of pie shapes consisting of (a) a half of a pie; (b) a third of a pie; (c) a quarter of a pie; and (d) a sixth of a pie.
In another feature of that aspect of the invention, the pipe wall structure includes a first conduit member and a second conduit member mounted within the first conduit member. The second conduit member has a continuous wall bounding the second passage. The second passage has a periphery and a cross-sectional area. The second conduit member continuous wall has an internal surface defining the periphery of the second passage. The second passage has a hydraulic diameter that is less than the dividend obtained by dividing the perimeter by xcfx80. In another additional feature, the second conduit member is free of convex portions.
In another additional feature of that aspect of the invention, the pipe wall structure includes a first conduit member and a second conduit member mounted within the first conduit member. The second passage has a perimeter xe2x80x98Pxe2x80x99, a cross-sectional area A and a hydraulic diameter DH. The second conduit member has a continuous wall having an inside surface defining the perimeter xe2x80x98Pxe2x80x99 of the second passage and A less than (P2/4xcfx80). In still another additional feature, the second conduit member is free of convex portions.
In yet another additional feature, the pipe wall structure includes a first, outer, conduit member having an inner wall surface and a second, inner, conduit member mounted within the first conduit member. The inner conduit member has an outer wall surface. The inner wall surface of the outer conduit member and the outer wall surface of the inner conduit member bound a region intermediate the outer conduit member and the inner conduit member. A third conduit member defines a third passage therewithin in side-by-side relationship to the second passage. The third conduit member is located in the region intermediate the inner wall surface of the outer conduit member and the outer wall surface of the inner conduit member.
In another additional feature of that aspect of the invention, the third conduit member has an outer wall surface. The outer wall surface of the third conduit member has a first portion engaging the inner wall surface of the outer conduit member and a second portion engaging the outer wall surface of the inner conduit member. In still another additional feature, the first portion of the third conduit member is shaped to conform to a portion of the inner wall surface of the outer conduit member. The second portion of the third conduit member is shaped to conform to a portion of the outer wall surface of the inner conduit member. In yet another additional feature, the region between the outer and inner conduits is annular. In another additional feature, the inner conduit member is concentric to the outer conduit member. In yet another additional feature, an annulus is defined between the inner and outer conduit members and the third conduit member occupies a sector of the annulus. In another additional feature of that aspect of the invention, a plurality of conduit members each occupy sectors of the annulus.
In a further aspect of the invention, there is a fluid displacement apparatus having (a) a motor unit having a first gearset having an output shaft, the output shaft having an axis of rotation defining an axial direction; an inlet by which fluid can flow to the first gearset, and an outlet by which fluid can flow away from the first gearset; (b) a gear pump unit mounted axially with respect to the motor unit, the pump unit having a second gearset connected to be driven by the output shaft of the first gearset; an inlet by which production fluid can be flow to the second gearset; and an outlet by which the production fluid can flow away from the second gearset; and (c) a transport apparatus having a first end and a second end, the second end being connected axially relative to the motor unit and the pump unit. The transport apparatus has a first passageway defined therein in fluid communication with the inlet of the motor unit by which fluid under pressure can be directed to the first gearset to turn the output shaft; and at least a second passageway defined therein in fluid communication with the outlet of the pump unit by which the production fluid from the second gearset can be conveyed to the first end of the transport apparatus.
In an additional feature of that aspect of the invention, the apparatus includes a plurality of the motor units connected axially together to drive the output shaft. In another additional feature, the apparatus includes a plurality of the gear pump units connected axially together.
In another additional feature, the transport apparatus has at least a third passageway defined therein. The third passageway is in fluid communication with the outlet of the first gearset to permit return fluid from the first gearset to be carried to the first end of the transport apparatus. In still another feature, the transport apparatus has another passageway defined therein by which electrical cabling can extend between the first and second ends.
In still another feature, the first and second passageways extend in side-by-side relationship. In a further feature, the transport apparatus includes a bundle of conduits defining the passageways, the bundle being mounted within a retainer. In yet another feature, the transport apparatus includes a plurality of modular pipe joints connected together in a pipe string. In another feature, the gear pump unit is free of ball and roller bearings.
In still another feature, the motor unit is mounted in a cylindrical housing, the housing having a production fluid passageway defined therein, the production fluid passageway being in fluid communication with the outlet of the second gearset and with the second passageway of the transport apparatus to permit production fluid from the gear pump to flow in the axial direction past the motor unit. In a further feature, the gear pump unit is mounted in a cylindrical housing, the cylindrical housing having porting defined therein to permit production fluid to flow to the inlet of the gear pump unit.
In a further feature of that aspect of the invention, the fluid displacement apparatus includes a plurality of the motor units mounted axially together and a plurality of the gear pump units mounted axially together. Each of the motor units has an axially extending pressure passage defined therein communicating with the inlet thereof, and an axially extending return passage defined therein communicating with the outlet thereof. The pressure passages of the motor units are in fluid communication to form a common high pressure passageway. The return passages of the motor units are in fluid communication to form a common low pressure passageway; and a plate is mounted between the motor units and the gear pump units to close off the high pressure and low pressure passages from the pump units.
In still another aspect of the invention, there is a well production apparatus for transporting a production fluid from a downhole portion of a well to a wellhead. The apparatus includes a transport assembly having a first end located in the downhole portion of the well and a second end located at the wellhead. A gear pump is connected to the first end of the transport assembly. The transport assembly has at least one passageway defined therein for conducting production fluid from the first end to the second end. The transport assembly has a power transmission member that extends between the first and second ends thereof The transmission member is connected to permit the gear pump to be driven from the wellhead. The gear pump is operable to urge production fluid from the first end of the transport assembly to the wellhead.
In another aspect of the invention, there is. a method of moving production fluid from a well to a wellhead. The method includes the steps of (a) mounting a gear pump to a first end of a transport apparatus; (b) introducing the first end of the transport apparatus into the well and locating the gear pump in the well; and (c) driving the gear pump from outside the well to urge production fluid from the production region to the wellhead.
In an additional feature of that aspect of the invention, the method includes the steps of providing a passageway in the transport apparatus for carrying production fluid from the production region to the wellhead; and providing a power transmission member to carry power for the wellhead to the gear pump. In still another feature of the invention, the method includes the steps of: (a) mounting an hydraulic motor to the gear pump; (b) providing a first passageway in the transport apparatus for carrying production fluid from the production region to the wellhead; (c) providing a second passageway in the transport apparatus for carrying hydraulic fluid to the hydraulic motor; and (d) supplying hydraulic fluid under pressure through the second passageway to operate the hydraulic motor and the gear pump. In a further additional feature, the method includes the step of providing a third passageway in the transport apparatus and directing a return flow of hydraulic fluid from the hydraulic motor through the third passageway to the wellhead.
In another additional feature, the method includes the steps of preparing a well bore having a horizontal production region, and introducing the gear pump into the horizontal production region. In another feature, the method includes the steps of: (a) preparing a horizontal production region of the well; (b) preparing a well bore above the horizontal production region; (c) introducing steam into the well bore, and (d) the step of driving the gear pump follows the step of introducing the steam into the well bore. In still another additional feature, the transport apparatus is a modular pipe joint apparatus and the method includes the step of incrementally introducing one pipe joint after another into the well. In another additional feature, the step of introducing includes passing the gear pump and the pipe joints through a well head blow out preventer.
These and other aspects and features of the invention are described herein with reference to the accompanying illustrations.